Schlumberger Technology Corporation

Vinegar Technologies LLC

Saudi Arabian Oil Company

Saudi Aramco

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Philip M Singer

Harold J Vinegar

George J Hirasaki

Xinglin Wang

Zeliang Chen

Henry N Bachman

Andrea Valori

Eva Vinegar

Tarek M Habashy

Shouxiang Mark Ma

Lalitha Venkataramanan

Patrice Ligneul

Chanh Cao Minh

Denise E Freed

Ravinath Kausik Kadayam Viswanathan

Richard E Lewis

Erik Rylander

Steve F Crary

Kamilla Fellah

Edward Alan Clerke

Fred K Gruber

Gabor Hursan

Benjamin Nicot

Johannes J M Buiting

Farhan Ali

Ahmed Al-Muthana

Yunke Liu

A method for separating liquid-like (T) from solid-like (T)H NMR transverse relaxation times in porous media uses novel pulse sequences together with aH NMR spectrometer optimized for geological core samples. The method is applied to obtain 1D Tdistributions and 2D T-Tmaps in organic-rich chalks for quantification of liquid-like signal (micropore fluids, meso-macropore fluids, fluids dissolved in organic matter, and clay-bound water) and solid-like signal (kerogen, bitumen, and clay hydroxyls). The novel pulse sequences comprise a solid-echo, which detects more solid-like signal than an FID. The method is used for fluid typing in micro/meso-macro pores, clay mineral identification, determination of kerogen content, and quantification of solvent-extracted bitumen versus bitumen expelled from kerogen due to swelling from dissolved hydrocarbons. The method is used to quantify the asphaltene, resin, aromatic, and/or saturate content of bitumen in the rock.

Method of determining solid and liquid components in sedimentary rocks using NMR relaxation

This invention is useful for determining the permeability of a geological formation usingH NMR diffusion measurements acquired in the laboratory and using downholeH NMR well logging. The current technology for obtaining formation permeability downhole using NMR is not adequate for low-permeability, unconventional source rock formations with high organic content. This new method uses laboratoryH NMR diffusion measurements for creating continuous downhole well logs of the mobile-hydrocarbon permeability of the hydrocarbon-filled pore space of downhole geological formations.

Method of estimating permeability using NMR diffusion measurements

The following invention is used for determining the relative permeability of a fluid in a rock for three different phases: water, oil, and gas, in both conventional and unconventional formations. The permeability of a phase describes how much it can flow in porous media given a pressure gradient and is useful in evaluating reservoir quality and productivity. The following invention is a method to determine the three-phase relative permeabilities in both conventional and unconventional formations using NMR restricted diffusion measurements on core with NMR-active nuclei, combined with centrifugation of the core. In addition, the tortuosity, pore size (surface-to-volume ratio), fluid-filled porosity, and permeability is determined for each of the three phases in a rock.

Determination of fluid-phase-specific petrophysical properties of geological core for oil, water and gas phases

New methods for determining the volumetric composition and saturation of methane and NGLs (natural gas liquids: ethane, propane, butane, and pentane) in a petroleum reservoir combining NMR (nuclear magnetic resonance) logging and NMR core analysis and for determining the mean pore-size and tortuosity of the light hydrocarbon-filled porosity in a petroleum reservoir using NMR core analysis.

Method for determining the composition of natural gas liquids, mean pore-size and tortuosity in a subsurface formation using NMR

A method for determining a wettability of a subterranean formation (or formation core) includes either deploying a nuclear magnetic resonance (NMR) logging tool in a subterranean wellbore or deploying a formation core sample in a laboratory based NMR tool. NMR measurements of the formation (or formation core) are obtained and used to compute the wettability. The NMR measurements are processed to generate a two dimensional diffusion relaxation map (a D/Tmap) which is in turn processed to compute the wettability.

NMR based reservoir wettability measurements

A method for testing an unconventional core sample is provided. The method involves loading the unconventional core sample into a sample holder and introducing fluid into the sample holder at an elevated pressure such that fluid is injected into the internal pore space of the unconventional core sample in order to resaturate the unconventional core sample with the fluid, wherein the fluid is selected from the group including a hydrocarbon fluid and a water-based formation fluid. An apparatus and a system used in combination with the method are also provided.

Workflow for resaturation and analysis of unconventional core samples

Methods are described for wettability characterization based on NMR measurements, which are sensitive to the surface wetting conditions of oil and water at the pore scale. The described methods make use of surface relaxation effects on the NMR relaxation (T). Workflows are described to obtain wettability profiles of a porous media such as a rock either in the native state or prepared to a certain state in the laboratory. An underlying forward model is also described for the mixed wet and fractionally saturated pore spectrum. Outputs of the described inversion include continuous saturation and wettability profiles as a function of the pore sizes in the porous media, as well as an averaged value for saturation and wettability over the entire pore spectrum.

Methods for determining wettability from NMR

A nuclear magnetic resonance (NMR) related distribution is estimated that is consistent with NMR measurements and uses linear functionals directly estimated from the measurement indications by integral transforms as constraints in a cost function. The cost function includes indications of the measurement data, Laplace transform elements and the constraints, and a distribution estimation is made by minimizing the cost function. The distribution estimation may be used to find parameters of the sample. Where the sample is a rock or a formation, the parameters may include parameters such as rock permeability and/or hydrocarbon viscosity, bound and free fluid volumes, among others. The parameters may be used in models, equations, or otherwise to act on the sample, such as in recovering hydrocarbons from the formation.

Estimations of nuclear magnetic resonance measurement distributions

Asphaltene content and its spatial distribution in a reservoir containing crude oil is an important factor in determining the potential for formation damage and pipeline impairment, as well as planning for processing and refining of the oil. Exemplary uses include: reservoir modeling, development and depletion planning, pressure maintenance, and surface facilities management. A convenient method has been developed which uses two-dimensional NMR techniques during a temperature and/or pressure cycle to quantify the asphaltene content of the crude oil without the need for extracting the oil from the reservoir rock. The technique can be applied to core, down-hole logs, or, a combination of both.

Asphaltene evaluation based on NMR measurements and temperature / pressure cycling

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Richmond, TX, United States of America

Philip M Singer